Down-hole actuating devices serve various purposes. Down-hole actuating devices such as balls, darts, etc. may be released into a wellhead to actuate various down-hole systems.
For example, in an oil well fracturing (also known as “fracing”) or other stimulation procedures the down-hole actuating devices are a series of increasingly larger balls that cooperate with a series of packers inserted into the wellbore, each of the packers located at intervals suitable for isolating one zone of interest (or intervals within a zone) from an adjacent zone. Isolated zone are created by selectively engaging one or more of the packers by releasing the different sized balls at predetermined times. These balls typically range in diameter from a smallest ball, suitable to block the most downhole packer, to the largest diameter, suitable for blocking the most uphole packer.
At surface, the wellbore is normally fit with a wellhead including valves and a pipeline connection block, such as a frachead, which provides fluid connections for introducing stimulation fluids, including sand, gels and acid treatments, into the wellbore.
Conventionally, operators introduce balls to the wellbore through an auxiliary line, coupled through a valve, to the wellhead. This auxiliary line would be fit with a valved tee or T-configuration connecting the wellhead to a fluid pumping source and to a ball introduction valve. One such conventional apparatus is that as set forth in U.S. Pat. No. 4,132,243 to Kuus. There, same-sized balls are used for sealing perforations and these are fed, one by one, from a stack of identically sized balls held in a (generally) pressurized magazine.
However, the apparatus appears limited to using identically-sized balls in the magazine stack during a particular operation. To accommodate a set of balls of a different size, however, the apparatus of Kuus requires disassembly, substitution of various components (such as the magazine, ejector and ejector sleeve, which are properly sized for the new set of balls) and then reassembly. The apparatus of Kuus, therefore, cannot accommodate different sized balls during a particular operation, since it is designed to handle only a plurality of same-sized sealer balls at any one time. To use a plurality of different sized balls, in the magazine, will result in jamming of the devices (such as in the ejector sleeve area).
Moreover, the ball retainer springs in Kuus do not appear to be very durable and would also need to be replaced when using a ball of a significantly different size. There is a further concern that the ball retainer springs could also break or come loss and then enter into the wellbore (which is undesirable). Additionally, there is no positive identification whether a ball was successfully indexed or ejected from the stack of balls for injection.
Furthermore, the device of Kuus is oriented so as to have the sealer balls transferred into the magazine by gravity and must therefore utilize a fluid flow line and valved tee through which well treating fluid and sealer balls are subsequently pumped into a wellbore. The device of Kuus, with its peculiar orientations of components, could therefore not be directly aligned with, or supported by, a wellhead.
More recent advance in ball injecting apparatus do feature a housing adapted to be supported by the wellhead. Typically the housing has an axial bore therethrough and is in fluid communication and aligned with the wellbore. This direct aligned connection to the wellhead avoids the conventional manner of introduce balls to the wellbore through an auxiliary fluid flow line (which is then subsequently connected to the wellhead) and the disadvantages associated therewith. Some of these disadvantages, associated with conventional T-connected ball injectors, include requiring personnel to work in close proximity to the treatment lines through which fluid and balls are pumped at high pressures and rates (which is hazardous), having valves malfunctioning and balls becoming stuck and not being pumped downhole and being limited to smaller diameter balls.
Examples of more recent ball injecting apparatus, which are supported by the wellhead, and are aligned with the wellbore, include those described in published U.S. Patent Application 2008/0223587, published on Sep. 18, 2008 and published U.S. Patent Application 2010/0288496, published on Nov. 18, 2010. Another example of a ball injecting apparatus supported by the wellhead and aligned with the wellbore is published U.S. Patent Application 2010/0294511, published on Nov. 25, 2010. Although these devices address many of the above issues identified with injection balls indirectly into the wellbore, i.e. via fluid flow lines, these still retain a significant number of disadvantages.
For example, it is know that the device taught in published U.S. Patent Application 2010/0294511, where each ball is temporarily supported by a rod or finger within the main bore. However, the pumping of displacement fluid through unit can damage or scar balls, especially if the displacement fluid is sand-laden fracturing fluid or if the balls are caused to rapidly spin on the support rod or finger. Such damaged balls typically fail to then properly actuate a downhole packer and fully isolate the intended zone. This then requires an operator to drop an identical ball down the bore which is extremely inefficient, time consuming, costly and can adversely compromise the well treatment.
The apparatus described in published U.S. Patent Application 2008/0223587, published on Sep. 18, 2008 teaches a ball magazine adapted for storing balls, in two or more transverse ball chambers, axially movable in a transverse port and which can be serially actuated for serially injecting the stored balls from the magazine into the wellbore. This overcomes a number of the disadvantages of the device taught in published U.S. Patent Application 2010/0294511. However, the invention contemplates loading the magazine externally from the ball injecting apparatus and, since the transverse chambers are transverse, cylindrical passageways or bores through the magazine's body with both horizontal and vertical openings, the plurality of balls can easily fall out of their respective chambers during preloading operations (i.e. through either entrance or exit openings). This could result in runaway balls on the surface next to the wellhead and potentially create a safety hazard. The design of this devices therefore makes the loading of the magazine difficult and time consuming, especially when loading a magazine with a large number of balls that must be monitored (i.e. to prevent the balls from exiting out through their respective entrance or exit openings) until placed within the axial bore of the apparatus.
Moreover, because the balls are serially positioned in a linear extending magazine, the ball injector of this patent application becomes cumbersome and unwieldy, especially when designed to work with 10, 12 or even 24 balls. For all practical purposes, the apparatus of this application is therefore limited to handling 5, or maybe 6, balls before becoming ungainly and unmanageable. As such, the applicant (of U.S. 2010/0294511) in a subsequent patent application, stated that this (earlier) apparatus retains a measure of mechanical complexity.
Published U.S. Patent Application 2010/0288496, published on Nov. 18, 2010, teaches a radial ball injection apparatus comprising a housing adapted to be supported by the wellhead. The housing has an axial bore therethrough and at least one radial ball array having two or more radial bores extending radially away from the axial bore and in fluid communication therewith, the axial bore being in fluid communication and aligned with the wellbore. Each radial bore has a ball cartridge for storing a ball and an actuator for moving the ball cartridge along the radial bore. The actuator reciprocates the ball cartridge for operably aligning with the axial bore for releasing the stored ball and operably misaligning from the axial bore for clearing the axial bore. This patent application also teaches that several of the radial ball arrays can be arranged vertically within one housing, or one or more of the radial ball arrays can be housed in a single housing and vertically by stacked one on top of another for increasing the number of available balls. For example, in one embodiment, it describes using an injector having two vertically spaced arrays of four radial bores so as to drop eight (8) ball.
However, published U.S. Patent Application 2010/0288496 suffers from a number of disadvantages including icing issues during winter operations which can result in the balls being frozen within their respective ball cartridges which have a cup-like body comprised of an open side, a lateral restraining structure and a supporting side for seating the ball during loading. However, during winter operations, the balls can become frozen within this cup-like body, thereby preventing proper release of the balls downhole. For that reason, U.S. Patent Application 2010/0288496 teaches that one should use methanol in the displacement fluid to reduce such icing issues. However, using methanol adds to the expense and complexity of the ball injection process.
Moreover, and although U.S. Patent Application 2010/0288496 teaches an indicator for indicating a relative position of the ball cartridge between the aligned and misaligned positions, this indicator does not indicate whether a ball was actually released from the cup-like structure, when placed in the aligned position, or whether it remains stuck and frozen within the ball cartridge, only to be retracted back into the radial bore when returned to the misaligned position. Therefore an operator of this apparatus cannot accurately determine whether a ball was successfully released from the injector as taught in this patent application.
A further disadvantage of the apparatus taught by U.S. Patent Application 2010/0288496 is that each of the balls are loaded through the axial bore of the injector by rotating the ball cartridge into a receiving position and then aligning each ball cartridge with the axial bore so as to be able receive a ball from above as it is dropped through the axial bore. This results in a time consuming an awkward loading procedure wherein balls are loaded serially, one after another, with each ball cartridge then being stroked between misaligned, aligned and then misaligned position. In an alternate loading procedure, this application suggest to pre-load the apparatus by removing the ball cartridges from each housing, seating the balls into each ball cartridge, and then reinstalling the loaded ball cartridges on each radial housing. This alternate loading procedure is also time consuming and awkward.
Additionally, in the primary suggested loading procedure, the balls will need to be carefully aligned along the axial bore and above its particular ball cartridge before being dropped, so as to avoid missing the ball cartridge and then having the ball continue on downward the axial bore. If a dropped ball does miss the intended ball cartridge and continues downward the axial bore then, in a best case scenario such as during pre-loading, the ball exits at the bottom end of the injector to be simply retrieved and loading can then be attempted again. However, if a dropped ball misses the intended ball cartridge when the injector is mounted to the wellhead structure or above a gate valve, then the injector will have to be disconnected from the wellhead or gate valve so as to then retrieve the ball. In a worst case scenario, a ball that is dropped in the axial bore and which misses the ball cartridge could prematurely be launched down the wellbore and premature activate one or more downhole tools (such as packers), resulting a ruined fracturing operation. As such the application even teaches use of a calibrated tubular or sleeve to assist with the loading of the balls through the axial bore. This additional piece of equipment adds further complication to the apparatus and loading procedure.
Another disadvantage of these prior art devices is that they all require that the plurality of balls are all subject to the pressurized environment of the wellbore, while they are waiting to be released into the wellbore. One disadvantage of having all of the ball subject to wellbore pressure is that additional sealing components and engineering specifications (e.g. to meet typical 10,000 psi pressure rating) are required for these devices, making such ball injecting apparatus more complex and more expensive than would otherwise be the case. Furthermore, such prior art ball injecting apparatus has a potential for many different pressure leak points; thereby creating a potential safety hazard. Another disadvantage of having all the preloaded balls subject to wellbore pressure is that the entire ball injecting apparatus will need to be depressurized in order to reload and/or change ball sizes.
As such, there remains a need for a safe, simple and efficient apparatus and mechanism for loading balls therein and for subsequent introducing such balls into a wellbore.